International oil companies (IOCs) sitting on large gas discoveries offshore Tanzania say they are keen to resume drawn out and currently halted talks over the development of liquefied natural gas (LNG) export projects, based on large reserves in south of the country. But, even if talks restart soon, the country will still face a struggle to start exports within the next decade given an increasingly competitive global LNG market.
Negotiations were paused by the government in mid-2019 to allow a review of Tanzania’s production sharing agreement (PSA) framework, the outcome of which has yet to be announced.
Tanzania’s overall recoverable gas reserves are estimated at more than 57tn ft³. These lie mainly in the country’s portion of the offshore Rovuma Basin, which it shares with southern neighbour Mozambique, where three LNG projects are already being developed utilising overall gas reserves estimated to be more than three times that size of Tanzania’s.
Norway’s Equinor, as operator, and partner ExxonMobil hold the license for Tanzania’s Block 2, which could hold more than 20tn ft³ of gas in place. Shell operates Blocks 1 and 4 in partnership with Ophir Energy, the UK independent now owned by Indonesia’s Medco, and Singapore-based Pavilion Energy. Those two blocks have estimated reserves of around 16tn ft³ of recoverable gas.
The ambitious target to begin project work within two years looks increasingly like a pipe dream
The two groups have been in separate development talks with President John Magufuli’s government for several years, even if the most likely outcome may well be, at least in the first instance, collaboration on a single plant. But a Host Government Agreement (HGA) needed to take any development further has proved elusive.
Disagreements over terms have stymied progress. Magufuli remains keen to maximise government revenues and domestic offtake, while IOCs have been seeking terms to make Tanzanian LNG more competitive with rival supply and to put the project’s finances on a stable footing.
The government’s ambitious target to begin project work within two years and have LNG production well before the end of the decade looks increasingly like a pipe dream. And the PSA review is not just an obstacle to resuming talks and unblocking progress on LNG projects, it also creates further uncertainty over the terms of future investment in offshore Tanzanian E&P.
IOCs are still, though, making positive noises, while stressing the need for terms that would make an export facility a worthwhile investment.
“Shell continues to engage with the Tanzanian government to progress the Tanzania LNG project. HGA negotiations with the government were paused in August 2019 to allow them to finalise the PSA review process. We look forward to resuming negotiations, which are vital in ensuring appropriate commercial and legal foundations for a globally competitive LNG plant,” the major tells Petroleum Economist.
Equinor stresses that it is in the mutual interest of both Tanzania and the companies in its group that the gas resources are developed but cautions that FID will likely to take some time to reach.
“Our priority is getting in place a financial framework through the HGA. Once an HGA is in place it will take several years to mature the project to a final investment decision, followed by construction start,” says the Norwegian firm.
With every month that goes by without an agreement, the rationale for a pre-2030 start to LNG exports weakens from the IOCs’ perspective, according to LNG market observers.
The jump in global LNG supply from 325mn t/yr in 2018 to 390mn t/yr, according to figures from consultancy Wood Mackenzie, while demand growth stutters and prices plunge is an immediate reminder of the risks of an abundantly supplied market to new project developers.
And while 2020s gas demand grow is expected to be healthy, the supply expansion field is already bunching. Qatar has plans to raise its LNG output from 77mn t/yr to around 110mn t/yr by 2024. In Mozambique, FID for ExxonMobil’s 15.2mn t/yr Rovuma LNG project is expected imminently, while Total’s neighbouring 12.9mn t/yr Mozambique LNG project and Eni of Italy’s 3.4mn t/yr Coral South FLNG project have already been greenlighted. A ‘second wave’ of mid-decade US Gulf of Mexico LNG liquefaction is also either post or rapidly approaching FID.
15.2mn t/yr Expected output of ExxonMobil’s Rovuma LNG project
Both Qatar and Mozambique are well placed to serve India and other south and southeast Asian markets that might be a natural home for any future Tanzanian LNG—whose exports would need to sell at more than $9/mn Btu to breakeven with current fiscal arrangements, according to Wood Mackenzie.
In contrast, it sees supply from Mozambique’s two large-scale onshore plants breakeven at less than $7/m Btu on greater economies of scale, more favourable terms for IOCs and closer proximity of reserves supplying the projects, enabling the two developments to share infrastructure. Due to associated liquids, Qatar’s LNG outcompetes any other project globally.
Outside of Qatar, any east African, US or other LNG liquefaction project planning for a mid-2020s start “will once again be targeting breakevens below or around the $7-$8/m BTU mark”, says Liam Kelleher, a Wood Mackenzie LNG market analyst. “So if I am putting a timeframe on when it would actually make sense to sanction the Tanzania project, given its current breakeven price, you are really talking the late 2020s or even into the 2030s.”
Other fish to fry
The leading IOCs in Tanzania are not short of alternative LNG projects into which to plough investment and expertise. Shell and ExxonMobil are both in the running to develop new Qatari trains and also have major North American projects lined up.
In Mozambique, the latter’s Rovuma LNG could cost around $30bn, while the former has signed up to buy 2mn t/yr from Mozambique LNG on a 13-year contract.
Equinor has a much smaller global LNG footprint than the two majors and wants to expanding its production beyond Norway. But, it is difficult to imagine the company going it alone in developing a Tanzanian LNG project without the support of another large player, says Kelleher.
Even the minor partners may not prioritise Tanzania. Medco’s Ophir deal was seen by analysts as attractive due to the UK independent’s southeast Asian assets, not its East Africa reserves. And Pavilion’s June 2019 purchase of LNG portfolio of Spanish utility Iberdrola—some 4m t/yr of sale and supply contracts—is likely to dominate its short-term LNG thinking.
President Magufuli’s very transparent desire to boost state revenues from resource projects also increase political and investment risk factors. January 2020 saw the resolution of a long-running gold mining row— which had halted exports of concentrates— when Canada’s Barrick Gold agreed to revised terms more favourable to the government on its operations.
These included a $300mn payment to the government to settle tax bills and other disputes, as well as the creation of a new joint venture to operate its mines, in which the government has a 16pc stake.
While this can be portrayed as a victory for the government—as it seeks to turn Tanzania from one of the world’s smallest economies into a middle-income country—the possibility of future changes to gas sector terms will give IOCs pause for thought.
As part of its push for economic growth, Tanzania also has plans to beef up its domestic gas pipeline network, which mainly fuels power stations and industrial plants. This domestic demand—running at 59bn ft³ in 2018, or less than 4.6mn m³/d according to the government—is mainly supplied from limited nearshore production in the south around Songo Songo island and in Mnazi Bay.
Government mandates to supply more gas domestically, with much lower payability, will hardly improve overall economics. But the volumes involved, given the low starting base, are unlikely to mean they are a project killer. If, though, the Tanzanian administration wants potentially transformative domestic supply within the next decade, it may have to concede that it will give ground on terms that will facilitate economic LNG export and thus any large-scale development of reserves.
First Published by The Petroleum Economist